This paper will discuss the case study of two (2) projects in Malaysia that were stretched-to-limit and optimized ‘on-paper’ all the wells’ related engineering design and construction, operation activities pre and during drilling campaign as well as logistic arrangement, which led to significant cost reduction in wells and thus improving the overall project economics. This significant savings achieved with full compliance to technical standards as well as with the betterment to improve HSE during offshore execution.

Coring and core analysis are considered the only direct and physical data to provide a true reflect to the reservoir properties. The measured properties are used to calibrate subsurface models and ensures close to reality properties. Representative data is critical to allow achieving such target. Coring planning and close follow up from the day decision is taken to core is important to achieve representative data. The approach followed in this manuscript allowed a high probability of successful core cutting, and representative core analysis. Field A is planned for appraisal phase and reservoir is expected to be of low permeability with sequence of shaly sands which adds complications to achieve the objective in cutting and analyzing the core. Different coring technologies were evaluated against the main coring objective of potential hydraulic fracturing field development. Conventional core is selected to offer the best value in both cost, and data coverage in compare to sidewall core. However, due to financial impact only one run was allowed, consequently it was critical to get the highest possible recovery and highest quality in one shot. An extensive planning phase investigated all variables to ensure high recovery. Rock strength and its mechanical properties allowed the selection of optimum coring parameters, coring accessories, and coring bit. It is critical to the project to collect the core and the added challenge of only single run required detailed workflow. Borehole size, mud wt, rate of coring and coring parameters were challenging due to the given one time opportunity. As a result, successful 100% core recovery is achieved, core retrieval to surface ensuring least core damage, this is demonstrated by CT scan which indicated no tripping out induced fractures. Well site core preservation reduced any weathering alteration, the selected stabilization method allowed minimal invasive to the core. Electrofacies guided by the whole core CT scans allowed the best coverage to the reservoir's properties. Long and large diameter plugs were achieved. Cleaning pilot study facilitated the selection of least damaging cleaning and drying method. Pilot small core analysis programs, and close follow up, and the analysis of raw data reduced the risk of unrepresentative core analysis results. Conventional core analysis data allowed refining and enhancing premeasurement electro facies and allowed a distinctive rock typing. The detailed planning permitted us to secure 100% core recovery and ensured core is reached the surface with least possible damage. The followed core analysis strategy reduced redundant experiments and allowed representative results at the same time optimized on the cost. This paper demonstrates the best practice that is followed in challenging environment of shaly sand sequences to successfully cut core and develop a program, and workflow which reflects the uncertainties to be solved.

This paper will discuss the Managed Pressure Directional Drilling fit-for-purpose solution deployed to meet drilling challenges in Mexico's offshore Homol field. This innovative solution integrates a new state-of-the-art Rotary Steerable System (RSS) with Managed Pressure Drilling (MPD) technology. Drilling hazards such as the ballooning effect due to drilling plastic formations, losses, wellbore instability, and stuck pipe were effectively mitigated, and improved drilling performance with reduced NPT was delivered compared to other directional drilling systems. The solution requires the integration of two highly technical disciplines, MPD and Directional Drilling. Hence, a Joint Operating & Reporting Procedure (JORP) and a defined communication protocol proved crucial for effective execution. The solution is based on a rigorous Drilling Engineering process, including detailed offset well analysis to deliver a comprehensive risk assessment and mitigation plan jointly with the Operator to tackle drilling hazards such as ballooning without compromising the directional drilling requirements. In addition, flow processes and procedures were developed for contingency events, including but not limited to losses, stuck pipe, wellbore instability, and well control. After successfully deploying the new RSS tool in Mexico offshore, the Operator came across a challenging directional well with a history of ballooning effect, losses, stuck pipe, and wellbore instability. Combining the RSS tool with MPD Constant Bottom Hole Pressure (CBHP) technique to mitigating the ballooning effect while maintaining constant surface back pressure (SBP), the well was drilled while minimizing the downhole pressure fluctuation to mitigate against wellbore instability until reaching the lower paleocene formation, taking care to maintain an equivalent circulating density (ECD) of 2.04g/cc while drilling, and 1.99g/cc during connections, in order to reduce the ballooning effect observed in offset wells. As a result of careful planning, the RSS and downhole-surface communication continued to work well, while the MPD CBHP variant successfully mitigated against ballooning and well control hazards. The paper will also discuss the effective communication protocol between directional drilling, MPD services, and rig contractors to ensure safe operational alignment. Rotary steerable systems (RSS) for directional drilling must drill in increasingly hostile environments and with different challenges inherent to formations; examples of this are formations with plastic behavior that cause ballooning effect. This phenomenon can confuse drilling crew cause its behavior is very similar to kicks from wells. Homol is an oilfield with marked ballooning characteristics, causing significant Non-Productive Time (NPT). Drilling challenges in the Homol field require the utilization of both Directional Drilling technology and MPD techniques to improve drilling performance and reduce NPT at the same time. However, the technologies need to be optimized for one another. Also, directional services had to ensure reliability and accurately position wells, while the MPD technology to discern ballooning from actual influx and managing wellbore stability. This article describes the teamwork carried out by the directional team and MPD to avoid/minimize the ballooning effect while drilling directional jobs, improving operational time. The paper also includes a planning and operational blueprint to reduce NPT related to, while increasing drilling performance in terms of rate of penetration (ROP) and wellbore quality to allow the liner to be run to section TD in the Lower Paleocene formation.

The advancement of technology in this era has long profited the oil and gas industry by means of shrinking non-productive time (NPT) events and reducing drilling operational costs via real-time monitoring and intervention. Nevertheless, stuck pipe incidents have been a big concern and pain point for any drilling operations. Real-time monitoring with the aid of dynamic roadmaps of drilling parameters is useful in recognizing potential downhole issues but the initial stuck pipe symptoms are often minuscule in a short time frame hence it is a challenge to identify it in time. Wells Augmented Stuck Pipe Indicator (WASP) is a data-driven method leveraging historical drilling data and auxiliary engineering information to provide an impartial trend detection of impending stuck pipe incidents. WASP is a solution set to tackle the challenge. The solution is anchored on Machine Learning (ML) models which assess real-time drilling data and compute the risk of potential stuck pipe based on drilling activities, probable stuck pipe mechanisms, and operation time. The output of the analysis is built on a warning and alarm system that can be utilized by the engineers to refine and optimize the well construction activities; tackling the stuck pipe issue before it manifests. This solution is evaluated by comparing historical and real-time drilling parameters with the prediction data to generate an error analysis. On top of that, a confusion matrix is tabulated based on the analysis of warnings and alarms raised by the solution to rule out Type 1 and Type 2 errors. The WASP solution has demonstrated tolerably accurate predictions of drilling parameters with minimal warnings and alarms error. With the solution, the stuck pipe issue can be identified hours earlier before the actual stuck pipe was reported in the historical well. It is a powerful tool with the capability to pinpoint possible stuck pipe mechanisms for engineer's immediate analysis and intervention. Value creation from the WASP solution has been massive with a reduction in manhours of analysis, potential NPT events, and unexpected operational costs. Data-driven techniques are effective in preventing stuck pipe incidents and will be scalable to tackle other downhole issues such as loss of circulation, well control, and borehole instability.

Well construction process through the unstable formations prone to total losses, pack-off and water influx is challenging. The manuscript describes the casing while drilling (CwD) combined with stage-cementing tool as introduced solution, when the challenge was to ensure that torque limit is not reached while drilling and estimate the effect of CwD on curing total losses and bring the casing while drilling performance to the level of conventional drilling. Introduction of CwD required extensive study of the potential torque while drilling as existing stage-cementing tools have low torque rating. Additionally, the casing fatigue may be a factor affecting the operations what lead to an introduction of magnetic particle casing inspection. The CwD bit design was adopted to the geological conditions based on best performance of the PDC bit, and originally selected drilling parameters were further optimized based on the result of the first runs. As the drilling of the well required utilization of mud cap for well control purposes, the mud recipes were adjusted to optimize the drilling performance and minimize the cost implication. The proposed solutions allowed to eliminate the problem with wellbore instability and related stuck pipe events. Further the proper engineering of the drilling process allowed significantly increase the rate of penetration since the beginning of the implementation, when the drilling torque never reached the limit even at 7,000 ft depth. The manuscript describes in detail the approach to make a proper design of CwD process focusing on prevention of existing problems and aiming to convert mitigation tool to a performance tool. Additionally, in details described the studied effect of CwD on curing total losses in highly fractured environment.

This paper describes a methodology that can be used to estimate the potential value of implementing digital and automation technologies in the well construction process in the context of a complex deepwater environment during the drilling conceptualization phase. This serves as a guideline for those interested in quantifying the value of applying digitization and automation processes, not only to make informed decisions related to investment in drillship or systems hardware and software but as well as performance improvement.

Gravel packing in a multilayer reservoir during an infill development project requires treating each zone individually, one after the other, based on reservoir characterization. This paper discusses the installation of an enhanced 7-in. multizone system to achieve both technical and operational efficiency, and the lessons learned that enabled placement of an optimized high-rate water pack (HRWP) in the two lower zones and an extension pack in the uppermost zone. This new approach helps make multizone cased-hole gravel-pack (CHGP) completions a more technically viable and cost-effective solution. Conventional CHGPs are limited to either stack-pack completions, which can incur high cost because of the considerable rig time required for multizone operations, or alternate-path single-trip multizone completions that treat all the target zones simultaneously, with one pumping operation. However, this method does not allow for individual treatment to suit reservoir characterization. The enhanced 7-in. multizone system can significantly reduce well completion costs and pinpoint the gravel placement technique for each zone, without pump-rate limitations caused by excessive friction in the long interval system, and without any fiuid-loss issues after installation because of the modular sliding side-door (SSD) screen design feature. A sump packer run on wireline acts as a bottom isolation packer and as a depth reference for subsequent tubing-conveyed perforating (TCP) and wellbore cleanup (WBCU) operations. All three zones were covered by 12-gauge wire-wrapped modular screens furnished with blank pipe, packer extension, and straddled by two multizone isolation packers between the zones, with a retrievable sealbore gravel-pack packer at the top. The entire assembly was run in a single trip, therefore rig time optimization was achieved. The two lower zones were treated with HRWPs, while the top zone was treated with an extension pack. During circulation testing on the lowermost zone, high pumping pressure was recorded, and after thorough observation of both pumping parameters and tool configuration, it was determined that the reduced inner diameter (ID) in the shifter might have been a causal factor, thereby restricting the flow area. This was later addressed with the implementation of a perforated pup joint placed above the MKP shifting tool. The well was completed within the planned budget and time and successfully put on sand-free production, exceeding the field development planning (FDP) target. The enhanced 7-in. multizone system enabled the project team to beat the previous worldwide track record, which was an HRWP treatment only. As a result of proper fluid selection and rigorous laboratory testing, linear gel was used to transport 3 ppa of slurry at 10 bbl/min, resulting in a world-first extension pack with a 317-lbm/ft packing factor.

Natural gas is the noble fuel of 21st century. Consumption increased nearly 30% in last decade. Exploitation of conventional, unconventional, and contaminated gas resources are in focus to meet the demand. There are number of giant gas fields discovered worldwide and some of them with higher degree of contaminants viz. CO 2 , H 2 S and Hg. Additionally, they have operating challenges of high pressure and temperature. It becomes more complex when discovery is in offshore environment. This study presents the development and production, separation, transportation and identification & evaluation of storage sites and sequestration and MMV plan of a giant carbonate gas field in offshore Malaysia. Geological, Geophysical and petrophysical data used to describe the reservoir architecture, property distribution and spatial variation in more than 1000m thick gas bearing formation. Laboratory studies carried out to generate the rock and fluid representative SCAL (G-W), EOS and Supercritical CO 2 -brine relative permeability, geomechanics and geochemical data for recovery and storage estimates in simulation model and evaluating the post storage scenario. These data are critical in hydrocarbon gas prediction and firming up the number of development wells and in the simulation of CO 2 storage depleted carbonate gas field. Important is to understand the mechanism in the target field for storage capacity, types of storage- structural and stratigraphic trapping, solubility trapping, residual trapping and mineral trapping. Study covers methodologies developed for minimization of hydrocarbon loss during contaminants separation and utilization of CO 2 in usable products. Uncertainty and risk analysis have been carried out to have range of solution for production prediction and CO 2 storage. Coupled Simulation studies predict the production plateau rate and 5 Tscf recovery separated contaminants profile and volume > one Tscf in order to have suitable geological structure for storage safely forever. Major uncertainties in the dynamic and coupled geomechanical-geochemical dynamic model has been captured and P90, P50, P10 forecast and storage rates and volumes have been calculated. Results includes advance methodologies of separation of hydrocarbon gas and CO 2 like membrane and cryogenics for bulk separation of CO 2 from raw gas and its transportation in liquid and supercritical form for storage. Study estimates components of sequestration mechanism, effect of heterogeneity on transport in porous media and height of stored CO 2 in depleted reservoir and migration of plume vertically and horizontally. Generation of chemical product using separated CO 2 for industrial use is highlighted.

In a difficult situation where the oil market is down, reducing drilling cost is always an interesting outlook to be pursued. To do so, one should consider looking at the highest component on the drilling cost. Down-hole equipment failure and stuck pipe is avoidable during the engineering planning. It is well-known that billions of dollars have been lost and numerous Bottom-Hole Assembly (BHA) are left in the well due to such problems, related to stick-slip phenomenon. Thus, despite the low oil price, it is a new normal that some asset owners opt to invest on high-end tools to prevent stick-slip, meanwhile others are still reluctant because of its high initial costs and chose to solely focus on the technical skills to drill faster. The objective of this paper is to determine whether, and which, utilization of these automations will be an effective method to lower overall cost, between using Anti-Stick Slip Technology (AST), Surface soft-torque, Self-Adjusting PDC Bit or all three combined together. The analysis of this project is conducted by providing conjecture in comparative method to visualize the configuration. In each case, estimated Rate of Penetration (ROP) is observed based on the recent literature of its application in similar lithology which is carbonate and interbedded shale. As the ROP increases, the overall drilling cost along with percentage of potential net saving for each case is evaluated in this study and select the most effective strategy. The outturn suggests that despite the high initial investment, combining all technologies are economically advantaged. With the DOCC by the self-adjusting PDC bit and torque alleviation by AST to handle the rock interface in addition to BHA torque wave mitigation from surface by surface soft torque, the ROP is quantified as summation of all cases’ ROP gained as the tool complements each other. The estimated ROP of the case significantly gives high decrement of the overall cost and boosted the potential net saving. Moreover, prevention from NPT due to downhole failure and stuck pipe problem is also a contributing factor to increasing cost efficiency. Therefore, combining all the tool together is proven to be the most favorable option aside from, respectively from preferable to the less, utilizing Surface Soft Torque, Self-Adjusting PDC Bit, and AST. Although it requires high initial investment, it is worthwhile to explore the usage of automation technologies for the overall cost reduction contributes to make the case financially attractive.

The Comalcalco Fault is a regional discontinuity that can present highly unstable zones when crossing it or its influence zone. This instability can lead to notorious increase in drag forces, cavings, stuck pipe events and ultimately loss of sections or the well. In the 12 ¼" hole of this exploratory well, this fault was present and despite some of the wells in the field managed to cross it without consequences, the influence was more notorious, and the problems lead to catastrophic results. While drilling the 12 ¼" section, the team was able to drill up to 4368 m without any relevant problems. The fault was intersected and drilled pass to section TD with the previous casing shoe at 2966 m. However, when a trip to surface was necessary, abnormal drag forces that avoided further movement of the string were experienced. This event led to the loss of the section and the need to perform a sidetrack, right across the influence zone of the fault at 3200 m. The risk was reassessed, and numerous preventive and mitigation measures were put in place, including drilling the section with a 12 ¼" pilot bit, enlarging the pilot hole to 13 ½" to cover the influence zone and having a contingency plan to run the 11 ¾" liner. Additionally, the formations were reinforced through drilling fluids design, and drilling and tripping strategies were optimized to minimize zonal invasion and influence zone disturbances that could lead to additional cavings. After the successful sidetrack, the section was drilled to 3600 m, 200 m below the fault’s influence zone. Good ROPs and low levels of stick and slip were observed despite several reaming runs while drilling. The contingency liner was run to TD, achieving the objective of isolating the influence zone of the Comalcalco Fault. With the problematic zone placed behind pipes, drilling the remaining of the original 12 ¼" sections with a 10 5/8" × 12 ¼" reamer resulted in the longest and fastest enlarged section to be realized in the field. With all the preventive measures put in place, the original 9 5/8" casing was set at its planned depth, avoiding an additional casing string and a change of the design of the completion.

MH oilfield is a fan delta deposited unconventional tight oil reservoir with complex lithology of volcanic rocks, metamorphic rocks, conglomerate, and claystone. The drilling efficiency was optimized by using the first-generation boundary mapping technology with Rotary Steering System (RSS) during the first batch drilling campaign (H2-2016∼H1-2017), which was mentioned in IADC/SPE-190998-MS. But with the development going further, more and more wells drilled into shale interbed causing low pay zone exposure, long drilling duration, and numerous drilling hazards. The overall drilling performance was not optimistic as before, the average Rate Of Penetration (ROP) decreased by 30.7% and the average footage per run decreased by 38.9% during horizontal section operation in some specific blocks of MH oilfield. By reviewing the detailed drilling and geology material of the first batch drilling, the challenges were defined. There is lateral irregular thin shale interbed existing in this conglomeratic reservoir which is rarely observed from the nearby wells in the first batch drilling zone. That unstable shale interbed with 0.5-2m thickness isolated the target into 2 to 3 components. The first-generation boundary mapping technology can only detect the nearest up or down boundary, with this limitation, it is difficult to reveal these laterally unstable shale interbed. It is crucial to precisely delineate the irregular thin interbed to develop this complex reservoir. Meanwhile, the bit selection which didn't catch up with the formation change is another issue that needs to be optimized timely. To solve the above challenges, the new generation boundary mapping while drilling technology was introduced to this project, it has 3 or more boundaries detecting ability at the same time, which can delineate the irregular thin interbed and optimize real-time Well Placement decision making. Meanwhile, the bit design and selection based on the timely geological data interpretation helped to improve drilling efficiency. This innovative integrated method deployed in phase II horizontal well drilling campaign proved to be an effective approach to optimize geosteering and drilling performance. The clear reservoir geometry delineation effectively helps avoid entering the irregular shale interbed in real-time, thus improve the pay zone exposure and trajectory smoothness. Till 2018, more than 50 wells were completed, the overall drilling performance of 2018 has been improved by 47.2% of footage per run and 42.2% of ROP compared with statistical results of H2-2017 of the M131 block and nearly back to the normal level. In this paper, the authors will demonstrate how this integrated approach helps optimize Well Placement, enhance drilling efficiency and save budget with some exemplary case studies. With this success, the authors believe this approach and techniques could effectively address the following horizontal well drilling campaign in this unconventional tight oil reservoir.

Field development for brownfields nearing their economic thresholds is always challenging, especially in offshore environments. As an operator, innovative approaches are necessary to reduce capital expenditures (CAPEX) and create attractive projects. A marginal cluster consisting of three fields, namely PN, NL, and PR, is expected to reach its economic limit in the next 2 years. This paper elaborates on single-trip completion technology as a catalyst for drilling one infill well in the PR field development project. In 2017, one appraisal well was drilled in a western area of PR field to validate the presence of oil. The scope of work included evaluating reservoir productivity and acquiring bottomhole fluid samples. A drillstem test with four multirate tests was executed for this reservoir. A horizontal development well named PA-02 was proposed and categorized as an extended-reach drilling well because of the drilling complexity. Most offshore wells in shallow-water environments are completed with a conventional well completion run that takes two or more trips, which normally takes more than between 5 and 8 days. Given expensive daily rig rates, the ability to reduce completion installation time was deemed vital to the economics of the project. If the installation incurs additional unnecessary project costs, it can cause the project to be economically unattractive. Using a collaborative approach, an interventionless, single-trip sand control system was designed and selected as the optimal completion solution to meet project demands. Radio-frequency identification (RFID) technology is one of the key enablers for the single-trip completion as it offers the utmost flexibility in both activation and contingency methods to deliver the necessary project cost reduction. At a time of uncertain global crude oil prices, the RFID-enabled single-trip completion concept discussed in this paper has become a beacon of light for operators in an otherwise dark period by allowing previously marginal or sub-economic projects to become viable. This technology has resulted in operational time savings of at least 27% compared to typical conventional two-trip completions in Malaysia offshore environments. Minimizing operational risk is also foreseen by reducing installation to a single integrated upper and lower completion trip. Selecting this RFID-enabled completion facilitated full deployment in one trip in the high-angle well, which eliminated the deployment of a tractor service for a 67% cost savings in this aspect alone. This method represented a paradigm shift in operational efficiency and will now be the operator’s strategic completion methodology when developing marginal fields. The deployment represents the first application of a single-trip completion in an economically challenging brownfield in the Malaysian offshore environment. The reduction in operational time and resultant savings in CAPEX proves that a single-trip completion offers an exceptional alternative to conventional methods in the shallow-water offshore environment.

The objective of this research is to describe the methodology used to drill the most extended reach well (ERD) in the Gulf of Thailand. The Jasmine field is a mature, sophisticated, oil field with many shallow reservoir targets that require a minimum 10,000ft horizontal displacement. As such, the main challenges faced, and the novel technology applied is described in detail by this research. The research is an example of successfully drilling a challenging well, safely and efficiently. The Jasmine C – Well X, is a 3-string design structure with an 11-3/4in top hole, an 8-1/2in intermediate section, and a 6-1/8in reservoir horizontal section. Well X was constructed by utilizing an existing platform well slot. The challenge involved drilling from the top hole to the kickoff point and directional drilling away from the casing stump of the existing well to avoid any collision with nearby wells emanating from the Jasmine C platform. The 8-1/2in hole section was the most important segment as it had to reach the landing point precisely in order to start the 6-1/8in section for GeoSteering in the reservoir section. The 8-1/2in section encountered three challenges that could affect drilling efficiency. Directional Drilling – The complexities of the well profile: The method involved making well inclination (INC) lower than 82deg in the tangent interval in order to reduce the well's tortuosity as much as possible. Hole condition – Hole cleaning and fluid losses control: The method involved the use of Low Toxicity Oil Based Mud (LTOBM) CaCO3 system, the chemical elements in the drilling fluid system could help to seal the high permeable zones. Drilling Engineering – Torque and Drag (T&D) control: The method taked into account the 7in casing run to the bottom of the hole, which the casing driven system did not allow for rotation The well was completed successfully without any additional trips. A Total Depth (TD) was of 13,052ftMD was achieved to reach reservoirs at 3,260ft TVDSS. It was therefore announced in 2019 as a new ERD record for Mubadala Thailand (ERD ratio = 3.26, Directional Difficulty Index (DDI) = 6.95). The top hole and 9-5/8in casing were set in the right depth. An 8-1/2in section was accomplished on the planned trajectory with an average on bottom Rate of Penetration (ROP) at 319 ft/hr. The 6-1/8in section was drilled by geosteering to achieve sub-surface objectives. A total of 2,143ft intervals inside the reservoir was successfully achieved. While drilling, lost circulation events occured, but the mud system was conditioned with Lost Circulation Materials (LCM). Therefore, drilling performance was unaffected. Moreover, the Bit's Total Flow Area (TFA) and Rotary steering systems (RSS) flow restrictor was configured to allow directional drilling at a very low Flow rate of 470gpm. Addition, 30 joints of 5-1/2in Heavy Weight Drill Pipe (HWDP) and 39 joints of 4in HWDP were added into the Bottom Hole Assembly (BHA) to transfer string weight to drill bitsand drill to well TD. As complexities of the well profile were fully aware, the casing was runned and minimized the open hole friction until the casing was deployed successfully. In the Gulf of Thailand, drilling the longest ERD well in a shallow True Vertical Depth (TVD) was clearly groundbreaking and entailed the successful management of the key operational challenges related to identification, job planning, design, technology selection, and implementation. This research illuminates the challenges and technical solutions of long ERD well and serves as an example of what can be achieved in the region and globally.

In the past few years, over hundreds of wells were drilled in Gulf of Thailand, had faced with the depletion and lost circulation issues resulted from a lack of pressure data. A prior research of reservoir depletion pressure ( Fangming, 2009 ) in oil field, China was obtained from multivariate statistic and regression by using density and neutron porosity log curves in logging-while-drilling data. However, the relative errors are 7.5% from the actual formation pressure. Thus, there are several latent variables in the model like drilling parameters ( Rehm, 1971 ) which part of formation pressure. From 2018 initiative model in Satun-Funan, the classification model was obtained by using mud gas, porosity, water saturation, net sand thickness, net-hydrocarbon-pore thickness and neutron-density separation. However, the limitation is drilling parameters could not account by classifier, and accurate only original pressure category. So, this study has expanded scope to include other reservoir properties and drilling parameters then applied with machine learning on offset well dataset by using three regressors such quantile, ridge and XGBoost regressors. The pore pressure estimation model aims to improve efficiency for making decision in execution phase, increasing confidence in perforation strategy. The model parameters, pay thickness, porosity, water saturation, original pressure from local pressure profile and total gas show are accounted into this model. As of regressor assumption, some facts are conducted to logarithm and perform 2nd polynomial feature for model flexibility. There are three steps for building model such as data manipulation, analysis and deployment. Two purposes of pressure prediction impact algorithm selection, for operational phase, quantile regressor is implemented to provide conservative prediction while Ridge or XGBoost regressors are alternatives for perforation strategy, provide mid case result of pressure prediction. Overall model performance was measured using root mean square error (RMSE) on train & test dataset which show approximately 1.2 and 1.5 ppg range of accuracy respectively from total 12 drilling projects in Pattani basin. Overall model fitting is within reasonable range of generalization capacity to apply with unknown data point (test set). The future model will continue to improve accuracy and manage imbalanced dataset between original pressure and depleted sands.

Coring during the development phase of an oil and gas field is very costly; however, the subsurface insights are indispensable for a Field Development Team to study reservoir characterization and well placement strategy in Carbonate formations (Dolomite and limestone with Anhydrite layers). The objective of this case study is to capture the successful coring operation in high angle ERD wells, drilled from the fixed well location on a well pad of an artificial island located offshore in the United Arab Emirates. The well was planned and drilled at the midpoint of the development drilling campaign, which presented a major challenge of wellbore collision risk whilst coring in an already congested area. The final agreed pilot hole profile was designed to pass through two adjacent oil producer wells separated by a geological barrier, however, the actual separation ratio was < 1.6 (acceptable SF to drill the well safely), which could have compromised the planned core interval against the Field Development Team's requirement. To mitigate the collision risks with offset wells during the coring operation, a low flow rate MWD tool was incorporated in the coring BHA to monitor the well path while cutting the core. After taking surveys, IFR and MSA corrections were applied to MWD surveys, which demonstrated an acceptable increase in well separation factor as per company Anti-Collision Risk Policy to continue coring operations without shutting down adjacent wells. A total of 3 runs incorporating the MWD tool in the coring BHA were performed out of a total of 16 runs. The maximum inclination through the coring interval was 73° with medium well departure criteria. The main objective of the pilot hole was data gathering, which included a full suite of open hole logging, seismic and core cut across the target reservoir. A total of 1295 ft of core was recovered in a high angle well across the carbonate formation's different layers, with an average of 99% recovery in each run. These carbonate formations contain between 2-4% H 2 S and exhibit some fractured layers of rock. To limit and validate the high cost of coring operations in addition to core quality in the development phase, it was necessary to avoid early core jamming in the dolomite, limestone and anhydrite layers, based on previous coring runs in the field. Core jamming leads to early termination of the coring run and results in the loss of a valuable source of information from the cut core column in the barrel. Furthermore, it would have a major impact on coring KPIs, consequently compromising coring and well objectives. Premature core jamming and less-than-planned core recovery from previous cored wells challenged and a motivated the team to review complete field data and lessons learned from cored offset wells. Several coring systems were evaluated and finally, one coring system was accepted based on core quality as being the primary KPI. These lessons learned were used for optimizing certain coring tools technical improvements and procedures, such as core barrel, core head, core handling and surface core processing in addition to the design of drilling fluids and well path. The selection of a 4" core barrel and the improved core head design with optimized blade profile and hold on sharp polished cutters with optimized hydraulic efficiency, in addition to the close monitoring of coring parameters, played a significant role in improving core cutting in fractured carbonate formation layers. This optimization helped the team to successfully complete the 1 st high angle coring operation offshore in the United Arab Emirates. This case study shares the value of offset wells data for coring jobs to reduce the risk of core jamming, optimize core recovery and reduce wellbore collision risks. It also details BHA design decisions(4"core barrel, core head, low flow rate MWD tool and appropriate coring parameters), all of which led to a new record of cutting 1295 ft core in a carbonate formation with almost 100% recovery on surface.

Monobore cementation is defined as where a single production tubing size runs from the pay zone all the way to surface and is cemented in place. This type of well design greatly reduce rig time and cost. The challenge however is to achieve a good cement in the annulus as a well barrier and to have a clean internal tubing after the cementing job to allow for successful production of the well. To achieve a clean internal tubing, a distinct bottom and top plugs were used as a means of mechanical separation. For fluids design, mud had to be thinned down prior to the cementing job and, a designed fiber based spacer system was used to physically scrub any mud-film sticking on the tubing walls. The centralizers and cement system were designed to allow for efficient displacement of mud and hence providing good overall placement and top of cement in the tubing-casing annulus. The cement in the annulus will be verified by pressure testing the annulus to 500 psi higher than previous shoe leak-off. This approach was implemented for the campaign of six wells, all designed with 5-1/2in monobore tubing. The bottomhole static temperature (BHST) of the well ranges from 300 to 350°F. The cementing system also had to be designed to cater to the challenge of this field, having CO2 as high as 60%, high temperatures, and a long open hole section that requires isolation and cement to set within a required timeframe. The cementing jobs were validated by no losses or gains during the job, floats holding at the end of the cementing job, differential pressure of cement prior to bumping the plug, density and pump rates executed as planned, accepted pressure test criteria of the annulus, output validation of cement contamination in pipe and annulus based on fluids and final well information. To further validate this system, the cement bond log was also run as part of the evaluation process and the cement log showed that zonal isolation was achieved. After the perforations, the perforation tool was pulled out to surface and the tool looked very clean with no signs of contaminated mud or cement around the tool. We demonstrate how this unique cementing approach can be a solution for the challenges of monobore cementing and one of the biggest problems of monobore cementing in the industry.

Based on the data of drilling rigs working in Malaysia from 2014 to 2020 as per shown below, it can be concluded that, historically the demand for rig in Malaysia is very dynamic and it was influenced by mainly the brent price albeit a delayed impact. The red line showed the Brent Price. With the dynamic of the demand, a systematic and well-organized methodology to develop an integrated rig sequence was essential. It is to ensure all rigs were planned accordingly and successfully acquire in time to ensure the projects can be executed as per expectation. A glimpse on the outcome of having an integrated planning between all the parties related such as host authority, project planners, procurement team, and rig planning team together with a right tool is essential to sequence and plan the projects and the drilling rigs requirement.

Field T is well known with its multiple layers of hard stringers that can go up to 25 ksi UCS at certain intervals, predominantly in 12-1/4" and 8-1/2" hole section. This can lead to stick-slip problem whereby the drill bit momentarily stalls due to high static friction, while the drill string keeps rotating. As a result, torque will buildup in pipe until it overcomes the friction at the bit, resulting in the drill pipe unwinding itself. Over time, this issue results in reduced drilling efficiency (i.e. lower ROP), eventually causing damage to the bit or worse, twisting off the BHA, which translates into high cost exposure to the Operator. During the exploration phase, the Operator required on average, 4 to 7 bit trips to drill 12-1/4" hole section and 2 to 4 trips were required to drill 8-1/2" hole section. The most reported reason to pull out of the hole were, BHA change out, downhole tool failure (DTF) and low rate of penetration (ROP). The bits’ inner & outer cutters were also reported to be damaged with dull grading as high as wear value of 7 or 8. Z technology is a torsional vibration mitigation system that uses wide band impedance (Z) matching concept that aims to absorb all torque waves arriving at top drive by overcoming inertia of motor & gearbox. The Z Technology changes the conventional hard boundary condition of a standard top drive (TD) RPM controller that is "stiff" (constant RPM) which results in full reflection of all torsional waves. A "stiff" TD control system leads to growth of standing waves (A combination of TD constant RPM & stick-slip "unwind" RPM) in the string which eventually may lead to torsional vibrations to the drill bit and/or motor housing/BHA. While drilling Development Phase 1B, Z Technology was seen to be effective in mitigating stick-slip. As a result, more mechanical specific energy (MSE) was available to be transmitted to the bit for formation rock removal. All three wells in the Phase 1B campaign managed to achieve the highest ROP in T field. This translated into cost savings in rig time and cost avoidance to Operator due to BHA damage. The paper will discuss the details of the Z Technology mechanism, its implementation and evaluating its effectiveness in minimizing torsional vibration due to the stick-slip issue.

In recent years, we have seen some refined drilling technologies crop up all over the world. These have given rise to implementation of remote centers to work on real time decision making with the wells. While drilling is in process, there are technologies that enable real time transmission of data and voice to and from remote sites, helping in real time intelligent commands and responses. It is hence now possible to form a single team of experts to monitor and control drilling operations. The development of remote operations in the oil and gas industry has evolved over years starting 2004 at different speeds in different regions of the world. For example, it took longer to reach the US land market because of resistance to change at the rig site. The decrease in oil prices in 2014 however, pushed remote operations into existence to reduce cost. Due to challenges such as either oilfield culture, company strategy, human factor, legal factor etc., it was not exactly the "norm". Fast forward to 2020 when the Covid-19 pandemic hit the oil industry into another slump, service companies have been pushed into the remote operations world. To learn with the times, this may be the new norm and maybe an excellent one. Many service companies have successfully performed operations wells globally increasing not only the efficiency of wellsite operations but also contributing to cost optimization and safety. During implementation, it is observed that remote operations are less a technical challenge, and more a value challenge requiring confidence from all stakeholders. In terms of drilling and operational efficiency, the results observed globally are significant, with fewer trips for M/LWD failure, as well as significant reductions in M/LWD NPT while drilling. This paper discusses the implementation of remote operations at global scale, lesson learnt on day-to-day basis, optimization opportunities, business workflow, positives such as business continuity, safety aspect and last but not the least, the environmental impact. The paper also talks of changes and effects of Covid-19 Pandemic on these operations. Remote operations prepare us well for such pandemic and it may be the safer way to operate now on. Also discussed are the keys to successful remote operations and various examples of remote operations establishments throughout the globe. Lastly a SWOT analysis is done to conclude how remote operations will help operators to add more value to operations and show that remote operations is the new future.

This paper will detail the engineering strategies utilized from design and planning stage up to and beyond the field execution stage which resulted in drilling the fastest well in a shallow water field, delivering superior drilling performance and successfully targeting the Upper Miocene (tertiary) reservoir in Mexico. From the 9 wells drilled in this field, the fastest well "Y"-200 was drilled with an average well construction index of 179 m/day when compared to the field average of 54.2 m/day. This shallow water field manifests several specific challenges which include tough drilling conditions, fluid property and hydraulic management, logging constraints and critical selection of casing setting depths. In order to enhance the drilling performance results to lower costs and improve production timelines, the project team performed a deep-dive into the well challenges and engaged with multi disciplinary teams and service providers to brainstorm different design improvements and operational practices. By doing so, the performance accelerates the 6000 to 9000 bbls of initial production estimated per well. The application of these creative engineering ideas proves that change, when applied correctly can really create lasting and proven improvements in drilling performance.